This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Coal deposits may hold significant amounts of hydrocarbon gases, such as methane, ethane, and propane, generally adsorbed onto the surface of the coal. A significant amount of natural gas reserves exists as adsorbed species within coal beds or as free gas within fractures (cleats) in the coal. The natural gas from coal beds, commonly referred to as “coalbed methane” (CBM), currently constitutes a major source of the natural gas production in the United States. Open fractures in the coal (called the cleats) can also contain free gas or can be saturated with water. Coal bed methane is often produced by reducing pressure, which reduces the partial pressure of methane in the cleats and causes desorption of methane from the coal. This pressure reduction can be performed by dewatering the coal bed. This, however, requires water handling and disposal.
Further, even using well stimulation methods, such as cavitation (see, for example, U.S. Pat. No. 5,147,111), only a small fraction of the CBM is economically recoverable. More specifically, depressurization is limited to higher permeability coal beds. This is because as pressure is decreased, coal cleats (i.e., natural fractures) may collapse and decrease the permeability of the coalbed. Loss of permeability is particularly a concern for deep coal beds, which may have a low initial permeability. Depressurization may also result in production of low-pressure gas needing significant power for compression to permit pipelining to market.
As an alternative to, or in conjunction with, depressurization, improved recovery of CBM may be obtained by injecting another gas into the coalbed. For example, CO2 may be used to enhance the production of CBM (see, for example, U.S. Pat. Nos. 4,043,395; 5,085,274; and 5,332,036). CO2 more strongly adsorbs to the coal than CBM and, thus, may displace adsorbed CBM. In other applications, nitrogen (N2), which less strongly adsorbs onto coal than CBM, may be used (see, for example, U.S. Pat. Nos. 5,014,785; 5,566,756; Scott R. Reeves, “Geological Sequestration of CO2 in Deep, Unmineable Coalbeds: An Integrated Research and Commercial-Scale Field Demonstration Project,” SPE 71749 (Society of Petroleum Engineers, 2001); and Jichun Zhu, et al., “Recovery of Coalbed Methane by Gas Injection,” SPE 75255 (Society of Petroleum Engineers, 2002). N2, and other less strongly adsorbing gases, lower the partial pressure of the CBM components in the bulk gas phase, which causes the CBM to desorb from the coal. Both of these methods can maintain the coalbed at relatively high pressures and hence aid permeability by keeping the cleat system open.
Other gases have also been described as enhancing production of coalbed methane or modifying coal beds for other purposes. For example, U.S. Patent Publication No. 2007/0144747 describes a process for pretreating an underground coal bed to enhance the potential for carbon dioxide sequestration. The method involves injecting hydrogen into an underground coal bed, wherein the hydrogen is at a temperature below about 800° C.; extracting hydrogen and methane from the coalbed; separating the hydrogen and methane; delivering the methane as a product of the process; and injecting the separated hydrogen into the deposit to continue the process. When the sequestration of carbon dioxide is desired, hydrogen may be optionally produced from methane and carbon dioxide may optionally be injected for sequestration.
The methods above are generally limited by the availability of the gas in sufficient amounts for injection. Larger amounts of injection gas may be generated by coupling a power plant to the injection process, wherein sequestration of the exhaust gases occurs in tandem with the production of energy. For example, in S. Reeves, “Enhanced Coalbed Methane Recovery,” presented in the SPE Distinguished Lecture Series, Society of Petroleum Engineers, 101466-DL (2003), the author discusses test projects for enhancing the production of coalbed methane from deep coal seams. The enhancement in the production of coal bed methane is related to adsorption isotherms. For example, N2/CH4 adsorption ratio is around 0.5/1, i.e., one unit of methane is adsorbed for every 0.5 units of nitrogen. In the case of CO2, CO2/CH4 adsorption ratio is 2/1, i.e., one unit of methane is adsorbed for every two units of CO2. In one project, N2 was used to lower the partial pressure of methane in cleats in the coal, enhancing the desorption of methane from the coal. Another project discussed was the use of CO2 from a pipeline to enhance production and sequester CO2 in the coalbed. The sources discussed for the N2 and CO2 were commercial pipelines in the region of the fields. The author does not discuss the isolation process used to generate the injection gases, or the use of mixed streams of N2 and CO2 for the injection.
In U.S. Patent Application Publication No. 2010/0326084, by Anderson, et al., a method for power generation using a low heating value fuel is disclosed. In the method, an oxy-combustor is used to combust oxygen with a gaseous low heating value fuel. A compressor upstream of the combustor compresses the fuel. The combustor produces a drive gas including steam and carbon dioxide as well as other non-condensable gases, which pass through a turbine to output power. The drive gas can be recirculated to the combustor, either through the compressor, the oxygen inlet or directly to the combustor. Recirculation can occur before or after a condenser for separation of a portion of the water from the carbon dioxide. Excess carbon dioxide and steam is collected from the system. The turbine, combustor, and compressor can be derived from an existing gas turbine with fuel and air/oxidizer lines swapped. The excess carbon dioxide can be sequestered, for example, by use in enhanced oil recovery, enhanced natural gas recovery, or in enhanced coalbed methane recovery.
However, in the application described above, the oxygen supply for the combustor is provided by an air separation unit (ASU) or any other system capable of providing a substantially pure oxygen stream. The application does not disclose the use of air as an oxidizer and, thus, does not disclose the generation or use of a combined N2 and CO2 stream.
In addition to supply issues, the cost of separation to isolate gases, for example, by a swing adsorption process or a cryogenic air separation unit from either the atmosphere or produced gases may be prohibitively expensive. Further, after separation, the gases may need substantial compression, e.g., 2500 psia or more depending on subsurface depth, for injection into a formation. Thus, techniques for improving the enhanced recovery of coal bed methane would be valuable.
Other related material may be found in at least U.S. Patent Publication No. 2005/0201929, U.S. Pat. Nos. 5,402,847; 6,412,559; and 7,491,250, and P. van Hemert, et al., “Adsorption of carbon dioxide and a hydrogen-carbon dioxide mixture,” 2006 International Coalbed Methane Symposium (Tuscaloosa, Ala., May 22-26, 2006), Paper 0615.